The present invention relates to subterranean fracturing operations. More particularly, the present invention relates to methods of initiating a fracture tip screenout and of determining the fracture initiation flow point during hydraulic fracturing operations.
Hydrocarbon-producing wells are often stimulated by hydraulic fracturing operations, wherein a fracturing fluid is introduced into a hydrocarbon-producing zone within a subterranean formation at a hydraulic pressure sufficient to create or enhance at least one fracture therein. One hydraulic fracturing technique involves discharging a work string fluid through a jetting tool against the subterranean formation while simultaneously pumping an annulus fluid down the annulus surrounding the work string between a work string and the subterranean formation. The stimulation fluid may be jetted against the subterranean formation at a pressure sufficient to perforate the casing and cement sheath (if present) and create cavities in the subterranean formation. Once the cavities are sufficiently deep, jetting the stimulation fluid into the cavities usually pressurizes the cavities. Simultaneously, the annulus fluid may be pumped into the annulus at a flow rate such that the annulus pressure plus the pressure in the cavities is at or above the fracture initiation pressure so that the cavities may be enlarged or enhanced. As referred to herein, the “fracture initiation pressure” is defined to mean the pressure sufficient to enhance (e.g., extend or enlarge) the cavities. The cavities or perforations are enhanced, inter alia, because the annulus pressure plus the pressure increase caused by the jetting, e.g., pressure in the cavities, is above the required hydraulic fracturing pressure.
As this hydraulic fracturing technique is often used in cases where other portions of the wellbore besides the enhanced fracture are taking fluid, commonly referred to as “fluid loss,” it may be important to know the flow rate of the annulus fluid at which the fracture initiation pressure occurs. As the flow rate is being increased, the added flow contributes to an increase in pressure. This pressure increase, in turn, causes an increased fluid loss, since fluid loss is a direct function of the differential pressure between the annulus pressure and the pore pressure in the formation. Further, increasing the flow will eventually allow the pressure inside the perforation cavity to be larger than the fracture initiation pressure, which may cause the cavities to be enlarged or enhanced as discussed above. As referred to herein, the “fracture initiation flow point” is defined to mean the flow rate of the annulus fluid, or other fluid that is experiencing fluid loss, at which the fracture initiation pressure occurs. For instance, if the flow rate exceeds the expected fluids loss at the fracture initiation pressure, then fracture initiation will occur. Therefore, the flow rate needed to combat fluid losses is the fracture initiation pressure.
Generally, the stimulation fluid suspends particulate propping agents, commonly referred to collectively as “proppant,” that are placed in the fractures to prevent the fractures from fully closing (once the hydraulic pressure is released), thereby forming “propped fractures” within the formation through which desirable fluids (e.g., hydrocarbons) may flow. The conductivity of these propped fractures may depend on, among other things, fracture width and fracture permeability. The permeability may be estimated by the size of the proppant. To generate sufficient fracture width, however, it may be necessary to obtain a fracture tip screenout in the formation. In a fracture tip screenout, the proppants bridge the narrow gaps at the tip of the fracture and are packed into the fracture, thus restricting flow to the fracture tip, which may terminate the extension of the fracture into the formation, inter alia, because the hydraulic pressure of the stimulation fluid may not be transmitted from the wellbore to the fracture tip.
Being able to control the initiation of a fracture tip screenout may be an important aspect of a successful fracturing operation. Without control of the fracture tip screenout, the fractures may not be packed with proppant as needed, e.g., to have the desired fracture width near the wellbore. Conventionally, to initiate a fracture tip screenout, the flow rate of the fracturing fluid is reduced while increasing proppant concentration therein, with the anticipation that this combination will cause a fracture tip screenout. However, this methodology does not consistently cause fracture tip screenouts. While increasing the proppant concentration and decreasing the flow rate does increase the probability that a fracture tip screenout may occur, this methodology assumes that there is one fracture taking all of the fluid. But, where there are competing fractures, the initiation of a fracture tip screenout may be difficult to control and/or predict using conventional methodologies. For example, in deviated wellbores, where only a portion of the perforations communicate with the dominant fracture that is being extended (when using conventional technologies), fluid is lost (e.g., leaking off) into other portions or fractures in the well besides the dominant fracture. Dependent upon the rate of fluid loss into the formation, these conventional methodologies may not successfully generate a tip screenout in the fracture. Furthermore, the conventional methods cannot predict when the screenout occurs, and, therefore, while it is desirable for the proppant to bridge at the tip of the fracture and pack therein, the bridging of the proppant and thus the screenout may occur anywhere in the fracture. Oftentimes, this may happen near the wellbore, before the high concentration proppant reaches the fracture, causing an undesirable screenout inside the wellbore. If the screenout does not occur at the tip, and the fracture is not gradually filled with proppant afterwards, the fracture may not be packed with proppant as desired.